The present invention relates to a system for allowing short term power augmentation of a gas turbine or gas turbine combined cycle power plant.
Electrical power grids are comprised of numerous power producers (power plants) and signifcantly more numerous users (residential and industrial customers). Stabile and reliable control of the grid requires active and continuous balance between electricity supply and demand. This is achieved by a combination of demand forecasting (to assure that a sufficient number of power plants are on line to meet anticipated demand, with margin), and automatic control of each power plant""s output as demand changes. Automatic power plant output control is in turn achieved through direct feedback of frequency error (deviation from either 50 or 60 Hz depending on where in the world the power plant is located) to drive a change in plant output.
If electricity supply exceeds demand, the grid frequency will increase above the target value. This positive frequency error will be detected by the power plant control system and cause fuel flow and plant output to reduce to bring the grid frequency back to the target value. When the frequency error is zero, the power plant""s output will stabilize. Conversely, if electricity demand exceeds supply into the grid, the grid frequency will dip below the target value. This negative frequency error will again be detected by the power plant control system and cause fuel flow and plant output to increase to bring the grid frequency back to the target value (provided the plant was not already at full load).
Under normal circumstances the frequency of electricity on a well operated grid will be extremely stabile. Most electricity customers are small in relation to the total electricity demand such that load increases are generally gradual and predictable. Power plants, on the other hand, can be quite large such that a trip event can significantly depress grid frequency as the remaining units respond. The potential for unplanned events to trip a power plant offline requires the grid to be operated with some reserve capacity at all times. Another reality of power generation is that power plants are generally most economical to run at full rated capacity. Those units running at full load are not expected to increase load when grid frequency falls, but they are expected to at least maintain their load through small variations from the target frequency, (typically 1%). Beyond this narrow frequency range power is allowed to fall, typically at the same rate as frequency; but not faster. These requirements are not a particular problem for some types of power plant such as hydroelectric or fossil fired steam plants since the grid frequency reduction does not impact the flow of working fluid (water to turbine, or air to the combustor). Such is not the case for gas turbine based power plants where the working fluid (air) is provided by a compressor spinning at a speed directly determined by grid frequency. In fact compressor airflow typically decreases more rapidly than grid frequency such that the natural tendency is for power output to fall significantly as grid frequency decreases. This is her compounded with large frequency dips ( greater than 1%) where the gas turbine may require additional airflow reduction, (via guide vane action), to maintain safe compressor operation.
As noted above, gas turbine and gas turbine combined cycle power output capability typically drops in direct proportion to a grid frequency (shaft speed) reduction, whereas the desired output response is inversely proportional to the grid frequency (shaft speed) such that the target grid frequency (shaft speed) tends toward its target value. One contributor to this behavior is the natural reduction in compressor inlet air flow with reduced shaft speed. The control system may additionally limit compressor air flow to maintain adequate margin against compressor surge, Fuel flow is also limited by combustion stability and parts life considerations.
Each of these alternatives have drawbacks with respect to providing a near instantaneous and predictable transient output increase in the case of an electric grid frequency reduction. Alternatives 1-6 may already be operating when the frequency reduction event occurs, such that no further output increase is possible. The output boost potential of alternatives 1-8 is also constrained by ambient conditions (e.g., high ambient humidity, or low ambient temperature) and so can not be depended upon to meet the total output boost requirement at all ambient conditions. Within a narrow range of the target frequency power output can be maintained by temporarily running the machine above its design firing temperature (constant fuel flow, reduced airflow) according to alternative 4. This solution will, however, rapidly reduce component life if relied upon too heavily for large frequency dips. Also, alternative 4 will provide the slowest response due to the large thermal heat capacity of the HRSG and steam working fluid. Water injection according to alternative 5 has been associated with increased combustion dynamic pressures and combustion system modification. Steam injection according to alternative 6 provides only a weak boost unless combined with supplementary firing of the HRSG, which is slow response.
Traditional control response to a grid frequency reduction is to increase air flow and/or firing temperature during the under frequency transient. Air flow can only be increased if the gas turbine is operating at less than base load when the event occurs, or the compressor capability was intentionally oversized to provide margin during these under frequency events, which is expensive. Over firing is the fastest response method of boosting gas turbine and gas turbine combined cycle power but is limited in amplitude by the strong relationship of firing temperature to gas turbine hot gas path parts life and maintenance costs.
A few power plants have been built to store energy during low load hours, typically overnight, for later use during peak hours. In the case of gas turbine and gas turbine combined cycle plants, this involves extraction of compressor discharge air to a storage vessel, typically an underground cavern, during low load hours, with subsequent retrieval of this stored air to supply the turbine working fluid flow, and hence output, during peak load hours. Application of this arrangement typically requires suitable geologic circumstances (the cavern) and specialized turbo-machinery and controls.
The invention provides a subsystem that enables a gas turbine or gas turbine based combined cycle power plant to maintain power output during large ( greater than 1%) and short duration (a few minutes) grid frequency reduction events without the need to drastically overfire the gas turbine above its rated firing temperature. The invention proposes an adaptation of the gas storage concept to the particular needs of a gas turbine or gas turbine combined cycle power plant faced with grid frequency support duties, i.e. intermittent short term power boost.
The invention provides a simple means for temporarily boosting the shaft output of a gas turbine or gas turbine combined cycle. As such, the system provides low cost, fast response, minimal plant cost and layout impact and simple operation. Three exemplary embodiments of the invention are described hereinbelow, each demonstrating a varying balance of cost and performance.
The invention is thus embodied in gas turbine/combined cycle system wherein a working fluid source is operatively coupled to the gas turbine system for selectively adding a working fluid to the gas turbine system downstream of the compressor and upstream of the gas turbine, to support a transient plant power boost via gaseous working fluid injection. The working fluid source is preferably at least one vessel containing pressurized and/or liquefied gas that is coupled via a flow control valve to the gas turbine system.